A Tangled Web

Complex factors shape differences in provincial electricity system policies and regulations that can spur or stymie investment

They are like the thick braids of transmission wire criss-crossing Canada: something constantly bending under winds of change, often fraying over time and sometimes snapping after storms. Political storms, that is. Just ask Ontario right now.

We’re talking about Canada’s complex snarl of provincial electricity market regulations; where no two provinces have harmonious rules over electrical power generation and development, electrical transmission, environmental assessments and other regulated aspects of the electricity market. Some provinces are so radically different in approach that one can be a welcoming Mecca for investment in its electrical system. And right beside it, another province has an inhospitable regulatory environment and monopolistic regime where a Crown corporation makes, sells and rules virtually every electron in the power grid. Newcomer businesses to those electricity markets need not apply.

The provinces, says Vancouver lawyer David Bursey, a member of the Energy Regulatory Practice Group at Bennett Jones LLP, each have “a whole series of different social, economic and political experiments” that affect the current state and development of their electrical infrastructure.

“We need predictability, certainty and a reasonable expectation of reaching decisions. It is really important for investment.” Without certainty and a more harmonious regulatory regime throughout Canada that makes it easier to get approvals for new facilities — from electrical power generation to transmission — “then you are doomed to the status quo,” suggests Bursey. That status quo includes aging electrical infrastructure in many provinces and regulations that thwart technological innovation at the expense of the environment and consumers.

 

All of this gives headaches to the lawyers who advise clients on matters on all sides of the electricity market spectrum — governments, First Nations, power-generator developers, transmission companies, private utilities and the huge investment entities behind the scenes. It also gives them plenty of work.

“Complicated regulatory regimes are how I earn my living,” says Toronto lawyer Adam Chamberlain with a bit of a laugh. A partner in Gowling WLG’s Toronto office, Chamberlain specializes in environmental law. He’s worked as counsel on electrical infrastructure matters in a variety of jurisdictions, including Ontario, Alberta, Nunavut and the Yukon. “It can be tricky as a lawyer to keep on top of all the jurisdictions. But for people like me who are kind of regulatory geeks, it’s also very interesting.”

In the two-plus decades Chamberlain has been practising, he’s seen plenty of change in electricity market generation and regulation across Canada. That’s particularly so in Alberta and Ontario; the two provinces where Crown corporations do not completely own the game, where there are varying degrees of market competition, and where the regulatory regimes most contrast with each other and the other provinces and territories.

Electrical generation in Canada, soon after 1881 when a steam-driven generator in Toronto lit up arc lamps around — what else — a hockey rink, had been the exclusive purview of provincial monopolies for much of our history.

One of the world’s first integrated public electrical utilities was the Hydro-Electric Power Commission of Ontario, founded in 1906, and renamed Ontario Hydro in 1974.

But about 20 years ago, notes Chamberlain, the provincial government started to break up one of North America’s largest electric monopolies, the Ontario Hydro electricity monopoly.

That process accelerated when the Ontario government introduced the Green Energy Act in 2009. Under that Act, Ontario committed to eliminating coal-generated electricity, which provided 25 per cent of the province’s electrical power. It shut down the last coal-powered plant in 2014. Meanwhile, Ontario’s Independent Electricity System Operator (IESO), responsible for electric supply procurement, sought out private companies to replace the provincially owned coal plants with cleaner natural gas and renewable resources such as wind and solar.

With the Green Energy Act’s introduction in 2009, Chamberlain says, “That really got Ontario going in terms of wind and solar and biomass generation. Now in Ontario we have an energy mix that looks a lot different than it did 15 or 20 years ago. Nuclear is the main base load now. Coal is gone.” Ontario now has a hybrid grid that is part government-owned and part deregulated.

 

Ontario and Alberta make for an interesting case study in policy and regulatory contrasts in approaching similar objectives, suggests George Vegh, head of McCarthy Tétrault LLP’s energy regulation practice. Vegh practises out of Toronto, mainly focusing on regulatory and wholesale market governance in the energy sector.

Alberta began to deregulate and privatize its electricity supply system in 1996. Unlike other provinces, Alberta has a complex wholesale market run by the Alberta Electric System Operator (AESO). It manages a power pool where electricity is constantly sold minute by minute by suppliers and bought by wholesale distributors through an auction system similar to the stock market.

What both Ontario and Alberta had in common was a commitment to eliminate coal-fired electrical generation. “When Ontario eliminated coal-fired generation, it was simple in that it was the owner of Ontario’s power generation,” explains Vegh. “So the shareholder — the government — basically just told its electricity producer (Ontario Power Generation Inc.) to stop burning coal. Then the only challenge was the province had to replace those facilities.”

In Alberta the problem is different. As of this year, Alberta began phasing out coal-fired electricity-generating plants. Last year it began imposing a $20-per-tonne carbon tax on emissions, which this year climbed to $30. Alberta’s new Climate Leadership Plan requires all coal-powered electricity plants meet zero emissions by 2030 or shut down.

But, after deregulation began, Alberta’s then government-owned generation, transmission and distribution capacity was sold off in chunks to private corporations. “Therefore,” says Vegh, “it has to engage in negotiations with the owners of those facilities to provide for compensation for the shutdowns before the end of the lives of those facilities.”

For example, in 2016 the Alberta government, in order to stave off lawsuits, agreed to pay three companies, Capital Power Corp., TransAlta Corp. and ATCO Ltd., a total of $1.36 billion for being forced to shut down six of their 18 plants early. Compensation for another 12 plants is still being negotiated.

Ontario’s ability to shut down coal plants was relatively “straightforward,” says Vegh. It owned them. But finding cleaner replacement power through contracts with new private-sector generation facilities proved a fiasco.

Ontario’s Liberal government, says Vegh, failed to follow the regulatory review process it set up to attract and contract with private companies to replace belching coal-fed electricity. In a scandal that forced the resignation of Premier Dalton McGuinty, the government compensated companies to the tune of $1.1 billion for the politically motivated cancellation of the planned construction of two natural gas plants.

Then there were Ontario’s unique regulations around pricing electricity from those new sources. In 2006, the government offered generous feed-in tariffs — the guaranteed prices per kilowatt hour of electricity provincially owned utilities would pay developers who built gas, wind and solar-powered generation facilities.

Those feed-in-tariffs, guaranteed by 20-year contracts, did just what they were intended to do — spur private-sector investment, development and modernization of Ontario’s aging electrical grid by reducing the risk of investment. For instance, the owners of solar-powered electrical generation facilities, which are more costly to build, were paid more per kilowatt hour than wind-powered developers.

And they were paid more than natural gas-powered electricity generators. It was a managed and subsidized competition by the province.

Since Ontario began to partially privatize its system in 2003, electricity bills for consumers have doubled. All in all, a scathing report by Ontario’s Auditor General about the Liberal government’s mishandling of the electrical systems’ overhaul revealed it cost taxpayers $9.2 billion more than it should have. The fiasco angered Ontarians so much that the June 7 election of Doug Ford’s Progressive Conservatives in a landslide victory that decimated former Premier Kathleen Wynne’s Liberal Party can partly  be attributed to Ontario’s electricity regulations and policies.

Meantime, Alberta took a different approach to modernizing its electrical grid. As of 2017, it has been subjecting all its new electrical-generation needs and coal-plant replacement to a competitive and more strictly reviewed bidding process under the Renewable Electricity Program (REP). Proposals approved in Round One totalling 600 megawatts of wind generation came in at $37 per megawatt hour, a record for lowest renewable electricity pricing. Alberta’s cost of new generation has been about half what Ontario consumers pay, says Vegh, though he adds that’s in part due to improvements in technology and lower costs for solar and wind build-out.

 

If there is a commonality between the provinces’ regulatory environments, it’s that all of them are, to varying degrees, lagging behind innovations in storage, distribution and smart technologies designed to reduce electrical consumption.

“The new interesting area of energy development is distributed energy resources,” says Toronto lawyer Ian Mondrow, who leads Gowling WLG’s energy regulation and policy practice. Distributed energy resources (DERs) produce controllable electrical loads directly connected to local distribution systems. Micro turbines, rooftop solar and small sewage gas or natural gas electrical generators are a few examples of DERs that can supply power to local buildings or neighbourhoods and, if needed, feed power back into a centralized grid for additional revenue or credits. Even a parked electric car could be considered a DER, as its batteries can store electricity that can be pumped back into a home should it need it.

“Increasingly,” says Mondrow, “policymakers are looking at smaller-scale distributed energy resources. They are closer to where the energy is going to be used. They are more modular; they can come in with smaller increments, so you don’t have to build a huge nuclear or hydro plant that costs billions of dollars.” Aside from being more environmentally friendly than conventional large-scale electrical generation, “they are much more dispersed so the grids are more resilient,” Mondrow continues. “If you have a big transmission line running across a province and there is a huge storm that knocks out the transmission line, that’s a problem. So you have to build redundant circuits and that is really expensive. And there is a question whether those assets will even be utilized in the future. They have 60 or more years of life.” But technology could render those expensive elements of a provincial grid obsolete.

Yet, especially in provinces such as Manitoba, Québec and Saskatchewan with monopolistic Crown-owned electrical generation and distribution systems, “One of the biggest barriers to distributed energy resources is whether a jurisdiction allows a generator to sell directly to customers or not,” explains Mondrow. “In those jurisdictions where there isn’t a competitive market like Ontario or Alberta, you can’t sell, generally, directly to an end user [only to a provincially owned utility]. That’s a barrier. It constrains the extent to which there are opportunities for developers.”

In some jurisdictions, Ontario for instance, you can build generation for yourself. But you can’t sell that electricity to a third party. Nor can you transmit that electricity across a municipal roadway, Mondrow notes, “which is a big barrier to having smaller neighbourhood [DER] systems.”

Yet in Saskatchewan, SaskPower, the provincially owned utility, can permit self-generation of electricity, even allowing distribution of that power from one property to another. “But it is up to them,” says Mondrow. “And so you have to go to the utility and get their permission.”

 

Climate change policies, environmental assessment rules, tariff rates, how provinces consult and negotiate with First Nations, morphing political ideologies — for everyone in the business of electrical energy, provincial variations in those factors affect investment certainty and decision making.

As Ontario’s June election results proved, electrons and elections are inextricably bound in Canada. Mike Richmond, Co-Chair of the Energy and Power Group at McMillan LLP in Toronto, knows that first-hand. He was the architect of Doug Ford’s energy platform, a critical campaign component in the PC victory.

Richmond previously served as Senior Energy Policy Advisor to Ontario’s Minister of Energy, responsible for overseeing the restructuring of the province’s electricity markets. He says Ford’s election will significantly change Ontario’s approach to electrical energy regulations. “For a number of years Ontario was offering major subsidies for renewable energy. And Alberta wasn’t. So they [developers] were all doing business here in Ontario.”

Those generous feed-in-tariffs for new projects in solar and wind or current ones once contracts expire are likely to end in Ontario with the new government, says Richmond. And, though he says Ontario will modernize rules around DERs, don’t expect such developments to get approved because, he says, Ontario is now saturated with electricity supply. “The policy that was announced is no more new contracts.”

Richmond agrees Canada has a complex and unharmonious electricity market regimes. “Canada is a tough market. There is uncertainty, in part because there are more factors and the rules change more often. That doesn’t stop investment. It’s just that level of uncertainty translates into a risk that gets priced into the investment decision. So to deal with that risk, investors need a higher rate of return here than they might elsewhere.”

At the end of the day he says, the clients he often deals with “don’t really care about political ideology … The key factor is where is the money? Who is paying me? If you pay me enough, I am willing to take on the risk of political involvement or regulatory complexity.”